Methods and apparatus for well productivity

ABSTRACT

A system and method for drilling a formation and a method for computing expected production from a wellbore in a formation and/or hydrocarbon reserves associated with the formation, the formation having a plurality of naturally-occurring fractures, the method including computationally modelling the formation; computing one or more wellbore positions intersecting some or all of the fractures; and computing an expected production from the wellbore at least partially based on an expected wellbore damage associated with a particular type of drilling technique.

TECHNICAL FIELD

The invention relates to the field of well productivity and inparticular, but not exclusively, well productivity from oil and gasreservoirs. The invention also relates to apparatus, systems and methodsfor well development and production such as, but not exclusively,systems and apparatus for drilling hydrocarbon reservoirs.

In some examples, the invention relates to well productivity from,development of and/or production from so-called unconventionalreservoirs, including shale oil/gas, coal seam gas, etc., although theinvention may apply to conventional reservoirs also.

BACKGROUND

Significant innovation and technological development has occurred inrecent years in relation to the development and testing of wells in theoil and gas industry. The ability to drill the most effective wellborein the most appropriate position for optimum field development can beimportant to the commercial success, or failure, of the well.

Typically, data are collected prior to any drilling operation in orderto try to determine the quality and properties of any subterraneanformation (e.g. seismic data). This permits an a priori assessment ofappropriate well trajectories, etc. However, regardless of the extent ofdata collection, uncertainties still remain and this can lead to poorerperformance of the well than expected.

A significant cost in establishing production from unconventionalreservoirs, both in terms of time and materials, can be attributed tochemical and/or hydraulic fracturing of the rock formation in order topermit production. Further costs are incurred when, due to a reductionin production, there is a requirement to re-fracture any formation. Atpresent, little consideration is given to these matters.

When developing from so-called unconventional reservoirs, such as thosehaving a low permeability (e.g. shale formations), it is expected thatsome form of chemical and/or hydraulic fracturing of the rock formationis required in order to permit production.

However, the process of hydraulic or chemical fracturing can introducefurther uncertainties due to the lack of predictability of the hydraulicor chemical fracturing process. In addition, hydraulic or chemicalfracturing can significantly increase the cost in establishingproduction from such unconventional reservoirs, both in terms of timeand materials. Further costs are incurred when, due to a reduction inproduction, there is a requirement to re-fracture any formation.

At present, little consideration is given to these matters, and sosuccessful development and production from a particular formation,particularly low permeability formations, cannot be guaranteed. Thereremains a desire to reduce the uncertainties and risk associated withdeveloping reservoirs, and in particular so-called unconventionalreservoirs, as well as improving the commercial viability of suchreservoirs.

This background serves only to set a scene to allow a skilled reader tobetter appreciate the following description. Therefore, none of theabove discussion should necessarily be taken as an acknowledgement thatthat discussion is part of the state of the art or is common generalknowledge.

SUMMARY

The invention relates to methods and apparatus to assist with wellproductivity, for example, well productivity from oil and gasreservoirs, and/or systems, apparatus and methods for well developmentand production, and in particular systems and methods for improving thecommercial viability of reservoirs. In some examples, the inventionrelates specifically to so-called unconventional reservoirs orformations, and provides a solution to effectively produce from suchformations without using hydraulic fracturing, or at least onlyfracturing to a minimal extent. The invention may find particularapplicability in relation to shale formations or coal beds.

In some aspects of the invention, there is provided a method forcomputing expected production from a wellbore in a formation and/orhydrocarbon reserves associated with the formation. This method may beused in exploration and/or appraisal of a formation, field or potentialfield.

That method may comprise computationally modelling a formation, forexample, having a plurality of naturally-occurring fractures. Theformation may be considered to be a low permeability formation, such asa shale formation. In such cases, the naturally-occurring fractures maybe spaced from one another, roughly at intervals, in the formation. Theformation may comprise a plurality of micro-fractures, between thenaturally-occurring fractures.

The method may comprise computing one or more wellbore positions, suchas appropriate, calculated and/or optimal wellbore positions,intersecting some or all of the fractures. The method may comprisecomputing the one or more wellbore positions at least partially based onexpected production from the wellbore. The expected production and/orreserves may be based on an expected wellbore damage associated with aparticular type of drilling technique, such as reverse-circulationdrilling. The one or more wellbore positions may be computed usingand/or based on the model of the formation. The computed expectedproduction of the wellbore may be for the wellbore in the one or morecomputed wellbore positions. The expected production and/or reserves maybe at least partially based on the inflow from naturally-occurringfractures, e.g. together with inflow from micro-fractures (e.g.micro-fractures that may have been minimally damaged by the particulartype of drilling technique).

The method may comprise subsequently deciding to drill and produce froma wellbore based on the expected production and/or reserves. The methodmay comprise subsequently deciding to alter the initially-computedwellbore positions based on the expected production. The method maycomprise determining the need to fracture a near-wellbore formationsurrounding the wellbore based on the expected production and/orreserves. The method may comprise re-computing one or more of thewellbore positions, intersecting some or all of the fractures, in orderto reduce, or eliminate, the need for hydraulic or chemical fracturing.

In other words, the method may comprise computing one or more of thewellbore positions in order to provide a particular (e.g. maximum)recovery from the formation, without hydraulic or chemical fracturing.

The method may comprise computing an expected production from a wellborein a formation and/or hydrocarbon reserves associated with a formationby,

-   -   computationally modelling a formation having a plurality of        naturally occurring fractures;    -   computing one or more wellbore positions, intersecting some or        all of the fractures; and    -   computing an expected production from the wellbore and/or        hydrocarbon reserves associated with a formation, based on an        expected wellbore damage associated with the particular type of        drilling technique, for example, reverse-circulation drilling.

The expected production and/or reserves may be based on the inflow fromnaturally-occurring fractures together with micro-fractures.

The method may comprise obtaining data, such as core data, fromappraisal wells drilled specifically using the particular type ofdrilling technique, e.g. reverse-circulation drilling, for the purposesof modelling the formation.

The data may be reviewed, and the formation potential may bere-appraised by computationally modelling the formation, e.g. using orbased on at least some of the data.

Since the above method better models the contribution from naturalfractures and/or micro-fractures, it may more accurately determine thefull extent of any exploration/appraisal well to be used for thehydrocarbon reservoir to be calculated. In addition, the impact of thenatural fractures and matrix mobility of hydrocarbons through input intothe reservoir model may be calculated, which may potentially improve thereserves booking of the asset owner, and/or may provide a determinationof the number of wells required for the development phase.

According to another aspect of the invention, there is a method ofdrilling a wellbore in a formation, for example, during explorationand/or appraisal of a formation, field or potential field.

The method may comprise drilling one or more wellbores into a formationhaving a plurality of naturally-occurring fractures. The wellbores maybe drilled so as to intersect some or all of the fractures (e.g. whereeach fracture is spaced from the other). The drilling may provide anexpected wellbore damage.

The method may include monitoring the drilling (or production) at thewellbore intersecting the fractures. The method may comprise choosingnot to fracture the wellbore based on the observed drilling/production.

According to a further aspect of the invention, there may be provided amethod of forming a wellbore in a formation, for example, duringexploration and/or appraisal of a formation, field or potential field.

The method may comprise using or determining parameters associated witha formation. The method may comprise computationally modelling theformation, for example, using the parameters. The method may comprisecomputing one or more wellbore positions, such as appropriate,calculated and/or optimal wellbore positions. The wellbore positions maybe based on drilling the formation, for example, usingreverse-circulation drilling or other advanced drilling techniques.

The method may comprise drilling one or more of the wellbore positions.The method may comprise using data associated with the drillingoperation to confirm one or both of the parameters associated with theformation and the computed model of the formation.

The method may comprise the method described in relation to any of theother aspects described herein. For example, the one or more wellborepositions may be wellbore positions associated with a particular,optimum or maximum recovery from the formation, e.g. as determined usingany of the above methods for computing expected production from awellbore according to one or more of the other aspects.

The method may additionally include altering, or modifying, one or moreof

-   -   (i) the determined parameters    -   (ii) the computed model; and    -   (iii) the wellbore positions,        based on an identified difference between data associated with        drilling, and expected data associated with the parameters or        model.

The method may include real-time monitoring of data while drilling, forexample, by using measurement/logging while drilling, and/or observingcuttings from a drilled location.

The method may be considered to be an integrated drilling solution.

According to a further aspect of the invention, there is provided amethod of forming a wellbore in a formation, the method comprising;

-   -   determining parameters associated with a formation;    -   computationally modelling the formation, and computing one or        more wellbore positions, e.g. appropriate, calculated and/or        optimal wellbore positions;    -   drilling one or more of the wellbore positions, and    -   using data associated with the drilling operation to confirm one        or both of the parameters associated with the formation and the        computed model of the formation.

In some aspects of the invention, there is provided a drilling system.The drilling system may comprise drilling apparatus, for example,reverse-circulation drilling apparatus.

The drilling system may comprise data-acquisition apparatus. Thatdata-acquisition apparatus may be in communication with the drillingapparatus, and may be configured to determine formation parameters, forexample, when drilling using the drilling apparatus.

The system may additionally comprise formation-modelling apparatus. Theformation-modelling apparatus may be configured to at least partiallyperform the method according to any of the above aspects and/or at leastone feature or method step described in relation thereto. Theformation-modelling apparatus may be configured to determine to expectedproduction from a wellbore in a formation and/or hydrocarbon reservesassociated with the formation. The formation-modelling apparatus may beconfigured to compute one or more wellbore positions, such asappropriate, calculated and/or optimal wellbore positions, intersectingat least some or all fractures in the formation. The formation-modellingapparatus may be configured to compute the one or more wellborepositions based on expected production from the wellbore, which may bebased on an expected wellbore damage associated with a particular typeof drilling technique, such as reverse-circulation drilling and/or maybe based on the inflow from naturally-occurring fractures, e.g. togetherwith inflow from micro-fractures.

The formation modelling apparatus may be in communication with the dataacquisition apparatus, and may be configured to use the, or any,determined formation parameters with a simulated model of the formation.For example, the formation modelling apparatus may be configured to usedetermined formation parameters in order to verify a simulated model ofthe formation (e.g. verify an a priori simulated model). The formationmodelling apparatus may be configured to use determined formationparameters in order to generate a simulated model of the formation (e.g.generate an a posteriori simulated model). In any case, this may allowfor control of the drilling apparatus based on the simulated model ofthe formation.

The system may be configured for use with low permeability formations,such as shale formations (e.g. shale gas and/or oil formation). Thesystem may be configured for use with coal-seam-gas formations (e.g.coal-bed methane).

The drilling apparatus may be configured to drill formations withoutunduly affecting a near wellbore formation (e.g. without causing damage,or significant damage, to the wellbore). In other words, the drillingapparatus may be configured to reduce the extent to which the formation(or near wellbore) is damaged during a drilling process, when comparedwith conventional drilling techniques.

The drilling apparatus may be configured to pass drilling fluid to andfrom any drill bit, via an annulus of a drill string (e.g. rather thanbetween the drill string and a bore wall). The drilling apparatus may beconfigured such that drilling fluid, having been returned to surface,may have been in contact only with the formation at a specific location(e.g. at, or around, the drill bit). The drilling apparatus may beconfigured to use compressed gas as a drilling fluid. The drilling fluid(e.g. gas) may be inert, or substantially inert, to the formation.

The drilling apparatus may comprise at least one flow control device.The least one flow control device may be configured to prevent anyundesired flow of hydrocarbons, or other fluids or gases, fromuncontrollably reaching the surface (e.g. when drilling throughoverpressured zones in the formation). In some examples, at least oneshut-off valve (e.g. blowout preventer) is provided as a flow controldevice. One, some or all flow control devices may be configured asdownhole devices, and optionally may be provided at or near a drill bitof the drilling apparatus.

In some examples, one, or some of the flow control device(s) are used toregulate the flow of fluids or gases from the formation to the dataacquisition apparatus. The flow control device(s) may be used to controlthe fluid/gas flow so as to permit the data-acquisition apparatus todetermine formation parameters at the region of the formation beingdrilled. Such flow control devices may permit isolation and testing ofselected zones in the formation.

The data-acquisition apparatus may be configured to sample materials,including produced liquids, gases and/or cuttings provided duringdrilling in order to determine formation parameters. The acquisitionapparatus may be configured to compute or determine the location ofnatural fractures in the rock formation, based on sampled materials fromthe well. For example, the data acquisition apparatus may be configuredto determine hydrocarbon production, or liberation, at a particulardrilling region or position. A determined change (e.g. increase) inhydrocarbon production may indicate the presence of a natural fractureat the drilling location. Similarly, a determined change (e.g. decrease)in hydrocarbon production at a drilling location may indicate that thedrill bit is no longer at a natural fracture.

The data acquisition apparatus may also comprise apparatus for otherdata measurements or analysis when drilling (e.g.measurements-while-drilling; logging-while-drilling, etc.). Formationparameters may include pressures, rock materials, inflow, hydrocarboncompositions, etc. The data acquisition apparatus may comprise, forexample, mass spectrometers, densitometers, liquid chromatographers,etc., in a known manner.

The data acquisition apparatus may be configured to determine formationparameters in real time (e.g. at the time of drilling), or relevant time(e.g. around the time of drilling). The acquisition apparatus may beconfigured to communicate determined parameters to theformation-modelling apparatus in real time, or relevant time (e.g. atthe time or drilling, or around the time of drilling, for example, whiledrilling continues).

The formation-modelling apparatus may be configured to use computationalfluid dynamics, for example using finite volumes, to model the formationbeing drilled.

The formation-modelling apparatus may be configured to use (e.g. verifyand confirm) a simulated model of the formation based on determinedformation parameters (e.g. confirm formation parameters are the same orsimilar to those modelled prior to drilling, or at least prior todrilling at that particular location). The formation modelling apparatusmay be configured to use, for example generate and/or revise, thesimulated model of the formation based on determined formationparameters (e.g. when the determined formation parameters are newlycollected, or differ from, from modelled formation parameters).

The formation modelling apparatus may be configured to model wellboreinflow. The formation modelling apparatus may be configured to assumelittle or no damage to the formation during drilling (e.g. based on useof the drilling apparatus). In other words, the modelling apparatus mayuse the determined formation parameters as accurately representing thequality or properties of the formation at a particular drillinglocation. This may be achieved when the drilling apparatus uses reversecirculation drilling.

The system may be configured to use the determined formation parametersin order to verify/generate/revise a simulated model of the formationand then control the drilling apparatus based on the simulated model ofthe formation.

Control of the drilling apparatus may include adjustment to expectedtrajectory of a drilled wellbore. Control may include adjustment to thelength of a wellbore. Control may include drilling of side branches, orthe like, from a wellbore. Control may include deviation of the wellborein order to increase natural fracture intersection, or area of exposureof natural fracture.

Control may include drilling a primary wellbore, for example, usingreverse circulation drilling. Control may include drilling one or moresecondary wellbores from the primary wellbore, for example, duringdevelopment of an existing field or wellbore or after an explorationappraisal of the formation. In some cases, each secondary wellbore maybe drilled in order to intersect one or more natural fractures in theformation. For example, the one or more secondary wellbores may bearranged to maximise a number of natural fractures intersected by thewellbores, e.g. by optimizing orientation or the secondary wellbore interms of azimuth and/or deviation angle. In this way, the requirementfor hydraulic fracturing may be minimised and/or the number of surfacelocations to be developed may be minimised.

The formation-modelling apparatus may be configured to update and/oroptimise the model or simulated model based on core data acquired forthe primary and/or secondary well bore(s). This may provide data for theformation in which the natural fractures and hydrocarbons are present.The coring procedures used to collect the core data may be known in theart, e.g. using the best existing operational standards to protect theintegrity of the data collected as an industry standard.

In some aspects of the invention, there is provided a drilling systemcomprising:

-   -   reverse-circulation drilling apparatus;    -   data-acquisition apparatus in communication with the drilling        apparatus, and configured to determine formation parameters when        drilling using the drilling apparatus; and    -   formation-modelling apparatus, in communication with the data        acquisition apparatus, and configured to use the determined        formation parameters with a simulated model of the formation so        as to allow for control of the drilling apparatus based on the        simulated model of the formation.

In other aspects of the invention, there is provided a method ofdrilling a wellbore. The method may comprise drilling, such as usingreverse-circulation drilling apparatus, to drill a wellbore. The methodmay comprise acquiring data from drilling in order to determineformation parameters. The method may additionally comprise using theformation parameters with, or to verify, a simulated model of theformation, e.g. so as to allow for control of the drilling apparatusbased on the simulated model of the formation. In some examples, themethod may comprise additionally controlling the drilling based on theverification.

According to a further aspect of the invention, there is provided amethod of drilling a formation.

The method may comprise drilling a primary wellbore usingreverse-circulation drilling apparatus. The method may comprise drillingone or more secondary wellbores from the primary wellbore, for example,during development of an existing field or wellbore or after anexploration/appraisal of the formation. Each secondary wellbore may bedrilled in order to intersect one or more natural fractures in theformation. For example, the one or more secondary wellbores may bearranged to maximise a number of natural fractures intersected by thewellbores, e.g. by optimizing orientation or the secondary wellbore interms of azimuth and/or deviation angle. In this way, the requirementfor hydraulic fracturing may be minimised and/or the number of surfacelocations to be developed may be minimised.

The or each secondary wellbore may be drilled using reverse-circulationdrilling apparatus.

The method may comprise permitting the well to flow during drilling ofthe primary wellbore. The method may comprise permitting the well toflow during drilling of the or each secondary wellbore.

The method may comprise determining the well and reservoir potentialduring drilling (e.g. determining hydrocarbon content and/or compositionfrom wellbore inflow during drilling).

The method may comprise isolating one or more of the secondary wellborefrom the primary wellbore during drilling. Isolation may be providedmechanically and/or chemically.

The method may be used in unconventional hydrocarbon reservoirs such asa shale formation (e.g. gas or oil type shale reservoirs). In suchexamples, gas may be accessible from low permeability sedimentary layersand natural fractures. The method may be used in coal bed methane orcoal seam gas type reservoirs where gas is accessed in coal deposits andthe natural fractures and cleats in the coal.

The method may comprise acquiring data from drilling in order todetermine formation parameters. The method may additionally compriseusing the formation parameters in order to verify a simulated model ofthe formation so as to allow for control of the drilling apparatus basedon the simulated model of the formation. In some examples, the methodmay comprise additionally controlling the drilling based on theverification, for example, in order to drill secondary wellbores.

In some examples, the method may comprise determining the location ofnatural fractures in the rock formation, based on sampled materials froma well in order to determine desired location(s) for secondarywellbores. The method may comprise determining hydrocarbon production,or liberation, at a particular drilling region or location in order todetermine the location of natural fractures (e.g. wherein a determinedrelative increase in hydrocarbon production indicates the presence of anatural fracture at that drilling region or location).

According to a further aspect of the invention, there is provided amethod of drilling a formation, comprising:

-   -   drilling a primary wellbore using reverse-circulation drilling        apparatus, and    -   drilling one or more secondary wellbores from the primary        wellbore, each secondary wellbore being drilled in order to        intersect one or more natural fractures in the formation.

The invention includes one or more corresponding aspects, embodiments orfeatures in isolation or in various combinations whether or notspecifically stated (including claimed) in that combination or inisolation. For example, any of the features or combinations of featuresdescribed above in relation to any of the above aspects may beapplicable individually or in combination to any of the other aspects.As will be appreciated, features associated with particular recitedembodiments relating to methods, may be equally appropriate as featuresof embodiments relating specifically to apparatus, and vice versa.

It will also be appreciated that one or more embodiments/aspects may beuseful or improving well productivity, and/or reducing costs.

The above summary is intended to be merely exemplary and non-limiting.

BRIEF DESCRIPTION OF THE FIGURES

A description is now given, by way of example only, with reference tothe accompanying drawings, in which: —

FIG. 1a shows an example of subterranean hydrocarbon-bearing formation;

FIG. 1b shows an example of a wellbore in a section of formationcomprising naturally-occurring fractures;

FIG. 2 shows a process of determining formation properties and thendrilling a wellbore;

FIG. 3 shows an integrated method for modelling and establishing awellbore;

FIG. 4 shows a drilling system; and

FIG. 5 shows a drilled formation comprising primary wellbore, and aplurality of secondary wellbore.

DESCRIPTION OF SPECIFIC EMBODIMENTS

The following examples are given in relation to what may commonly beconsidered to be an unconventional reservoir. However, it will beappreciated that the invention need not be so limited, and may beapplied to many different types of reservoirs.

FIG. 1a shows an example of a subterranean hydrocarbon-bearing formation100 (e.g. comprising oil and/or gas), which extends beneath a surface110. In this example, the formation 100 can be considered to be a lowpermeability reservoir, such as a shale-rock formation or coal-bedmethane formation, or the like.

Within the formation 100 there may be present a number ofnaturally-occurring fractures 120. Those fractures 120, depending on thegeology, may be typically spaced from one another by particularintervals. Between those intervals, there may additionally be numerousmicro-fractures, formed in the formation 100. The naturally-occurringfractures 120 have been greatly simplified for ease of understanding,and the micro-fractures have not been included in the figure for thesame reasons.

Typically, when the existence of such a formation 100 is suspected,further analytical data is accumulated, such as lithography assessments,structural geological characteristics, as well as potential drillingdata from the local area, and other such data. This cumulative data canbe used to estimate a suitable location for a well, and approximate thepotential recovery from any such drilled well.

This information is then passed to a drilling contractor who isresponsible for drilling wellbores into the formation, using thesuitable locations for the wellbores. During such drilling operations,it is common for the formation 100 (e.g. that formation extending arounda wellbore) to become damaged, for example due to egress of drillingfluids or the like, into the near-wellbore formation (i.e. the formationsurrounding the wellbore). Further, if the permeability of the formation100 is expected to be comparatively low, such as one might expect in ashale formation, or the like, then the drilled well may subsequently befractured, for example hydraulically, in order to increase the recoveryfrom the reservoir. In some cases, the location of the wellbore may beselected based on the orientation of the naturally-occurring fractures120 or to ensure it passes through brittle rock such that, whenfractured hydraulically, production from the formation 100 can beincreased, or at least initially increased. In other words, where theformation 100 is expected to be unconventional, or of low permeability,the location of the wellbores are selected with an a prioriunderstanding that the well will be fractured subsequently.

By way of an example, FIG. 1b shows a section of the formation 100through which a wellbore 130 has been drilled. Here, the wellbore 130has been drilled horizontally.

While such hydraulic or chemical fracturing may indeed increase theinitial production from the formation 100, the use of fracturing fluidmay significantly increases the overall costs of drilling the well inthe formation 100. Further, wells that have been developed by initiallyhydraulic or chemical fracturing the formation can require some amountof re-fracturing later in the lifecycle of the well. Without being boundby theory, this may be due to the formations propensity to return tooriginal natural state, after hydraulic or chemical fracturing iscomplete. Any such re-fracturing of the well again increases costs.

Development of well using existing techniques, and relying on hydraulicor chemical fracturing to maximise potential production, can beineffective and overly costly. There remains a desire to reduce theuncertainties and risk associated with developing reservoirs, and inparticular so-called unconventional reservoirs, as well as improving thecommercial viability of such reservoirs.

The above-described process is represented by FIG. 2. Here, at a firststep 210 the properties of a formation are assessed. When confirmed thatthe formation has particular characteristics, for example, lowpermeability, low porosity, or the like, then hydraulic or chemicalfracturing of the well is agreed. Any well design is then based onexpected subsequent hydraulic or chemical fracturing. In a second step,220, the well design is passed to a drilling contractor who drills andfractures the well. Optionally, re-fracturing 230 may be required atsome point in the lifecycle of the well.

There is a need to improve the above described process in order toreduce, mitigate, or entirely obviate the need to fracture a well.Further, there is need to improve the ability with which the propertiesof a formation 100 are understood, and the formation drilled, in orderto maximise production from each particular well.

To achieve this, the following described example of data accumulationand drilling may be considered. This is also generally shown in FIG. 3.This methodology may be applicable to exploration and/or appraisal of aformation, field or potential field, for example.

In a first step 210, properties of the formation 100, or reservoir, maybe assessed. This may be considered to be a data review. Here, dataaccumulated regarding the formation 100 may include one or more of datafrom lithography assessments, structural geological characteristics, aswell as potential drilling data from the local area. This may includeother data such as one or more of data from initial drilling reports,logging data, well tests, etc.

Simply by way of an example, the data may be derived from one or moreof: core data, reservoir-rock distribution data; Borehole Image Data(BHI) data; Petrophysical Data (e.g. TOC determination); data associatedwith Interpreted Depth Structure and Faults; Fracture Characterisationdata; and/or geomechanical analysis data, etc.

The accumulation of the formation properties may permit the assessmentof the overall anticipated reservoir quality.

In a second step 220, an optimised well design may be created. This maybe achieved by initially creating a reservoir and well design usingfinite volumes and computational fluid dynamics, specifically formodelling subterranean regions. An example of such a method is describedin U.S. Ser. No. 12/788,166 (Method of Modelling Production from aSubterranean Region), which is incorporated herein by reference in itsentirety. The use of such methodology allows for the modelling of theformation 100 as a single fluid flow system, making no physicaldistinction between reservoir, or near-wellbore, inflow and well flow.This method may be considered more accurate than other inflowpredictions and requires no correction, connection, fudge or skinfactors. It enables evaluation of the optimum well geometry.

During the modelling process, drilling techniques, includingreverse-circulation drilling, are considered when selecting the suitablelocations for wellbores. Reverse-circulation drilling may be consideredto operate differently from conventional drilling techniques because,broadly speaking, drilling fluid flows to and from any drill bit, viathe annulus of a drill string, rather than between drilling string andthe bore wall. An example of reverse-circulation drilling is disclosedin U.S. Pat. No. 6,892,829B2 (Two String Drilling System), which isincorporated here in its entirety.

The use of reverse-circulation drilling techniques may reduce the extentto which any formation 100 is damaged during the drilling process, whencompared with conventional drilling techniques. Further, given thatdrilling fluid returned to surface is likely to have been in contactonly with the formation 100 at a specific location (e.g. at the drillbit), then accurate measurements can be made as to formation 100properties at that drill bit, when assessing that drilling fluid atsurface (e.g. assessing cuttings). This may be used in addition to otherdata measurements or analysis when drilling (e.g.measurements-while-drilling; logging-while-drilling, etc.), as will befurther explained.

The model may include potential completion designs, diagrams andgeometry, together with potential well options and trajectories.

The method of modelling may allow for an expected production from awellbore in formation 100 and/or hydrocarbon reserves associated withthe formation to be computed. This may be achieved by computationallymodelling, as above, the formation 100 in which a plurality ofnaturally-occurring fractures 120 are present, together with one or morewellbores intersecting those fractures 120. In exemplary formations 100,those fractures 120 will be spaced from each other and consideration maybe given to the potential for inflow from micro-fractures, existing inaddition to the naturally-occurring fractures 120. For example, givenuse of reverse-circulation drilling in which the formation 100 may bedamaged only to a limited (or no) extent, an approximate inflow frommicro-fractures existing between natural fractures 120 may be computed.This may be based on the position of one or more appropriate wellbores,intersecting some or all of the fractures. In some examples, the welltrajectory may be selected to maximise the potential inflow from thenaturally-occurring fractures 120 together with the micro-fractures.This may include deviated wellbores at between 30 and 60 degrees fromvertical (e.g. 45 degrees).

Expected production from the wellbore 130 and/or hydrocarbon reservesassociated with the formation may then be computed, based on an expectedwellbore damage associated with reverse-circulation drilling (and otherparameters associated with the wellbore 130). This may allow for anoptimised well design to be achieved. Optimising the well design in thismanner may obviate or at least mitigate the need for subsequenthydraulic or chemical fracturing of the wellbore 130. In other words,what may be considered to be unconventional reservoirs may be exploitedwithout the need for subsequent hydraulic or chemical fracturing of thewells in order to achieve suitable production and recovery rates. Thismay be achieved by the use of reverse-circulation drilling together withexploitation of natural fracture and micro-fractures at the wellbore130.

In some examples, the method may include the recovery of core data fromappraisal wells drilled specifically using reverse-circulation drilling.In those examples, such data may be reviewed, and the formationpotential may be re-appraised. In those cases, a model for thosere-appraised wells may be generated based on the data from thereappraisal.

In a third step 330, the optimised wells may be drilled usingrecommended well trajectories derived from the computational modellingprocess. The drilling may use reverse-circulation drilling techniques,as expected in the model. To assist with successful drilling, downholeshut off valves may used with reverse-circulation drilling, which areknown in the art.

For example, the reverse-circulation drilling may make use offlow-control means, or downhole blow-out preventers (downhole BOP). Anexample of such a BOP for use with reverse-circulation drilling isdescribed in U.S. Pat. No. 8,408,337B2 (Downhole Blowout Preventor),which is incorporated here by reference in its entirety. Such a devicemay be useful in preventing hydrocarbons or indeed other fluidsuncontrollably reaching the surface (e.g. in overpressured horizons).

Other reverse circulation techniques may be used, such as thosedisclosed in U.S. Pat. No. 7,343,983B2 (Method and Apparatus forIsolating and Testing Zones During Reverse Circulating Drilling), whichis incorporated herein by reference in its entirety.

In addition, the drilling may include cementing, for example,specifically cementing used for reverse-circulation drilling. Suchcementing may enable drilling though water and loss zones (e.g. of lowpermeability or pressure), whereby the reverse-circulating cementing iscan be used to isolate a particular region of the formation, such as ashallow aquifer or other water bearing or loss zones. This may allow forthe development of wells in sensitive, populated areas without impactingon, for example, the shallow water zones. Examples ofreverse-circulation drilling using cementing are describing in U.S. Pat.No. 7,540,325B2 (Well Cementing Apparatus and Methods), which isincorporated here in it entirety.

It will be appreciated that the above isolation of water zones, etc. maybe incorporated into the model.

During the drilling process, parameters associated with a formation 100may be determined. This may be achieved by assessing cutting,measurement-while-drilling, logging-while-drilling, etc. Data derivedfrom the drilling operation may be used to confirm one or both of theparameters associated with the formation (e.g. step 310) and thecomputed model of the formation 100 (e.g. step 320).

In some examples, that data may be accumulated and used in real time. Inother words, data may be accumulated and the model may be updated toensure that the appropriate location of each well is still beingprovided. For example, the method may include altering, or modifying,one or more of: the determined parameters: the computed model; and thewellbore positions, based on an identified difference, or significantdifference, between data associated with drilling, and expected dataassociated with the parameters or the generated model (e.g. 310 and/or320). Further, the method may allow drilling data interpretation in realtime to allow improvement in operational decisions. That data mayinclude pore pressure, wellbore stability, tool failure risks, and otherdrilling problems, which may prompt a change in optimised well design,and so a change to expected drilling.

The above described methods, and as shown in FIG. 3, integrates threedistinct processes previously unconsidered or performed. This allows thepotential to develop oil and gas reservoirs more successfully than haspreviously been possible. This is particularly so in formations of lowpermeability, where the use of hydraulic or chemical fracturing iscommon place.

It will be appreciated that the above methodology may find particularapplication in older formations, or what may be considered to be morefractured formations. Further, it will be appreciated that, when usingthe above methodology, the most appropriate wellbore may be drilled inthe formation for that given low permeability formation, reducing orentirely eliminating any need to fracture or indeed re-fracture thewell.

In some examples, the method may comprise an initial data review of anexpected formation 100, and then initial modelling of an approximationof location of wellbores (e.g. using reverse circulation drilling).Subsequently, validation and confirmation may be obtained that drillingand production may occur, cost-effectively, without the need forhydraulic or chemical fracturing of the formation. This may beconsidered to be a feasibility study. Subsequently, a full model may begenerated and drilling can occur.

The following example provides a manner in which the above integratedworkflow may be implemented:

Phase One—Data Review

-   A review of the available data may be conducted to include one or    more of the following:    -   Review of the core data    -   Review of the core reservoir rock distribution    -   Review of Borehole Image Data (BHI)    -   Review of Available Petrophysical Data in the Well(s)—total        organic carbon (TOC) calculation, etc.    -   Review of Interpreted Depth Structure and Faults    -   Review of Fracture Characterisation Studies    -   Review of geomechanical analysis (or do a fit for purpose        analysis)

Phase Two—Well Placement 1. Reservoir Property and Stress Analysis

Data, such as seismic data, may help to characterise the reservoirs,such as shale gas reserves, in terms of structural features, formationheterogeneity, rock properties, and stress, etc.

Application of one or more of the following seismic attributes may allowfor identification of appropriate location for well placement in orderto optimize well placement, reduce the drilling risk andminimize/mitigate or eliminate any need for hydraulic fractureoperation:

-   -   Post-stack seismic amplitudes    -   Structural attributes such as 3D curvature and coherency    -   Physical attributes like spectral decomposition    -   Attributes based on trace shape similarity. This may be useful        in detecting changes in facies, lithology, and rock properties.

2. Reservoir Rocks Geo-Mechanical Properties

Appropriate locations for wellbore may include areas where the shale isbrittle. Those areas also respond favourably to hydraulic fracturing.Areas that are already folded and faulted increase the likelihood ofnaturally-occurring fractures.

-   -   Modelling and mapping shale brittleness using seismic inversion        and well data available to identify these wellbore locations and        estimate their properties distribution, for example, in 3D.

Feasibility

The rock physics feasibility study can be performed using key wells withthe best well log information available and any existing post-stack andpre-stack information available around the well locations. This activitymay include one or more of the following:

-   -   Definition and validation of the rock physics model to use.        Possibility to test different methodologies available.    -   Elastic property estimation and crossplot analysis. Consistent        multi-well elastic moduli analysis will help determine        correlations with the reservoir properties such as lithology,        porosity and fluids, which allow an efficient Amplitude        Variation with Offset/Amplitude Variation with Azimuth        (AVO/AVAZ) based reservoir description.    -   Resolution analysis to examine the minimum resolvable thickness        in seismic analysis.    -   Fluid Substitution and AVO modelling. Different realistic fluid        saturation scenarios will be produced at the well locations and        we will produce synthetic gathers for each case.    -   Seismic data quality analysis to screen any seismic        pre-conditioning process that may help to reduce the uncertainty        and increase the resolution.

Data useful for this analysis includes: existing well database andexisting seismic volumes, CRP gathers at well locations if available.

Full Field Extension 1. Azimuthal Seismic Analysis

Analysis of either amplitude, velocity/impedance or coherence/curvaturevariations with azimuth, which may give an indication ofanisotropy/fractures. Existing azimuthal processing (all existingazimuth stacks) may be helpful in order to perform this work. Thisincludes:

a. Pre-Stack Depth Migration (PSDM) Migrated Azimuth Stacks

b. PSDM Migrated gathers

c. PSDM Angle stacks

d. Interpreted horizons

e. Acquisition and Processing reports

f. Well logs particularly P and S velocities (cross diapole sonic ifexists) and density logs

g. Petrophysics database interval velocity from PSDM

2. Simultaneous AVO Inversion

Existing migrated PSDM gathers may be used to estimate elasticproperties that can be used to describe the lateral extension ofpetrophysical properties such as porosity, lithology, etc, as definedduring the feasibility stage.

Pre-stack information may be helpful for this process, and CentralReference Point (CRP) gathers if they exist are also helpful for thisprocess. This includes

-   -   PSDM Full Azimuth Angle Stacks    -   PSDM Migrated gathers    -   Interpreted horizons    -   Acquisition and Processing reports    -   Well logs. Particularly P and S velocities (cross diapole sonic        if exists) and density logs    -   Petrophysics database    -   Interval velocity from PSDM

Subsequent to the above assessments, drilling and production may occur,cost-effectively, without the need for hydraulic or chemical fracturingof the formation. Data generated from drilling may be used to update themodel and/or data parameters in order to optimise well location andultimate production.

Consider now FIG. 4, which shows generally a drilling system 1200according to one exemplary embodiment. The system 1200 is configured foruse with low permeability formations, such as shale formations (e.g. oiland/or gas). The system 1200 may be configured for use withcoal-seam-gas formations (e.g. coal bed methane).

The system 1200 of FIG. 4 can optionally be used with or modelled by theprocess described in relation to FIG. 3, although it will be appreciatedthat this need not be the case and instead the process of FIG. 3 couldbe applied to other drilling arrangements and similarly, the drillingsystem of FIG. 1200 need not be used with the process described aboveand could instead be used with other processes and procedures.

Here, the drilling system 1200 comprises drilling apparatus 1210, whichin this example is shown as reverse-circulation drilling apparatus 1210.The drilling apparatus 1210 is configured to drill a formation withoutunduly affecting a near wellbore formation (e.g. without causing damage,or significant damage to the wellbore). In other words, the drillingapparatus 1210 is configured to reduce the extent to which the formation100 (or near wellbore formation) is damaged during a drilling process,when compared with conventional drilling techniques.

As is shown in FIG. 4, the drilling apparatus 1200 is configured to passdrilling fluid to and from a drill bit 1212, via an annulus 1214 of adrill string 1216 (e.g. rather than between drilling string 1216 and abore wall 1218). The drilling apparatus 1210 may be configured such thatdrilling fluid, having been returned to surface, may have been incontact only with the formation at a specific location (e.g. at thedrill bit). Similarly, only hydrocarbons produced or liberated at thedrilling location will be produced to surface.

In this particular example, the drilling apparatus 1210 is configured touse compressed gas as a drilling fluid. That drilling fluid (e.g. gas)may be inert to the formation 100.

Here, the drilling apparatus 1210 further comprises at least one flowcontrol device 1220. As is shown in FIG. 4, the flow control device 1220can be configured as a downhole device, provided at, or near, the drillbit 1212 of the drilling apparatus 1210.

Of course, in alternative examples, the flow control device may beprovided additionally or alternatively at surface.

Here, the least one flow control device 1220 can be configured toprevent any undesired flow of hydrocarbons, or other fluids or gases,from uncontrollably reaching the surface (e.g. in when drilling throughoverpressured zones in the formation). In some examples, at least oneshut-off valve (e.g. blowout preventer) is comprised with the, or each,flow control device 1220. Such flow control devices 1220 are known inthe art.

In some examples, one, or some of the flow control device(s) 1220 can beused to regulate the flow of fluids or gases from the formation to dataacquisition apparatus 1230 of the system 1200 (as explained in moredetail below). In such a manner, the flow control device(s) 1220 may beused to control the fluid/gas flow so as to permit data-acquisitionapparatus 1230 to determine formation parameters at the region of theformation 100 being drilled. Such flow control devices 1220 can permitisolation and testing of selected zones in the formation 100.

Here, the data-acquisition apparatus 1230 of the drilling system 1200 isspecifically configured to determine formation parameters in real time,or at least relevant time, when drilling the formation 100. Relevanttime may be considered to be within a time frame that permits drillingdecisions based on determined formation parameters that, although notinstantaneous, are nevertheless applicable given the rate of change ofdrilling or rate of change of formation 100.

While shown for ease here as apparatus 1230 provided at a drill rig 1235(e.g. at surface), it will readily be appreciated that some or all ofthe data acquisition apparatus 1230 may be provided downhole (e.g.logging-while-drilling apparatus, measuring-while-drilling apparatus,etc.). In such a manner, the data-acquisition apparatus may be provideddownhole and/or at surface. The data acquisition apparatus may comprise,for example, mass spectrometers, densitometers, liquid chromatographers,etc., in a known manner. A skilled reader will readily be able toimplement the various embodiments accordingly.

Here, that data-acquisition apparatus 1230 is in communication with thedrilling apparatus 1210 so as to determine formation parameters, forexample, when drilling using the drilling apparatus 1210. Formationparameters may include pressures, rock materials, inflow, hydrocarboncompositions, etc. In “communication” can include “fluid communication”(e.g. when determining composition of fluids, cuttings, etc., producedfrom the drilling location), as well as “signalling communication” (e.g.electrical, electromagnetic, optical, acoustic, etc.), when determiningformation parameters using one or more sensors associated with thedrilling apparatus 1210.

In such a manner, the data-acquisition apparatus 1230 can be configuredto sample materials, including produced liquids, gases and/or cuttingsprovided during drilling in order to determine formation parameters. Inthis example, the acquisition apparatus 1230 is specifically configuredto compute or determine hydrocarbon production, or liberation, at aparticular drilling region or position. In such a manner, it is possibleto determine the location of natural fractures in the rock formation,based on sampled materials from the drilled well. For example, adetermined change (e.g. increase) in hydrocarbon production may indicatethe presence of a natural fracture at the drilling location. Similarly,a determined change (e.g. decrease) in hydrocarbon production at adrilling location may indicate that the drill bit 1212 is no longer at anatural fracture.

As is shown in FIG. 4, the system 1200 additionally comprisesformation-modelling apparatus 1240. That formation modelling apparatus1240 is in communication with the data-acquisition apparatus 1230, andis configured to use the determined formation parameters with asimulated model of the formation (e.g. a priori simulated model, or aposteriori simulated model). As will be explained, this may allow forcontrol of the drilling apparatus 1212 based on the simulated model ofthe formation.

Here, the formation-modelling apparatus 1240 is provided on a computer,comprising a processor and memory in a known manner, together with (inthis example) a user interface 1245 (shown here as a keyboard 1246 andgraphical interface 1247). Of course, it will readily be appreciatedthat the formation-modelling apparatus 1240 may be provided on adedicated hardware, such as field programmable gate arrays,system-on-chips, or even across a network of computers (e.g. within anetwork cloud).

In this example, formation-modelling apparatus 1240 is configured to usecomputational fluid dynamics, for example using finite volumes, to modelthe formation 100 being drilled.

In some examples, a well design may have been created prior to drilling.In other examples, the model may be generated during drilling. Eitherway, the model may be generated by initially creating a reservoir andwell design using finite volumes and computational fluid dynamics,specifically for modelling subterranean regions. An example of such amethod is described in U.S. Ser. No. 12/788,166 (Method of ModellingProduction from a Subterranean Region), which in incorporated herein byreference in its entirety. The use of such methodology allows for themodelling of the formation 100 as a single fluid flow system, making nophysical distinction between reservoir, or near-wellbore, inflow andwell flow. This method may be considered more accurate than other inflowpredictions and requires no correction, connection, fudge or skinfactors. It enables evaluation of the optimum well geometry.

In this example, the formation-modelling apparatus 1240 is configured touse (e.g. verify and confirm) a simulated model of the formation 100based on determined formation parameters received from thedata-acquisition apparatus (e.g. confirm formation parameters are thesame or similar to those modelled prior to drilling, or at least priorto drilling at that particular location). In some examples, theformation-modelling apparatus 1240 is additionally or alternativelyconfigured to generate and/or revise the simulated model of theformation based on determined formation parameters (e.g. when thedetermined formation parameters are newly collected from, or differfrom, the modelled formation parameters.

Here, the formation-modelling apparatus 1240 is configured to modelwellbore inflow. That wellbore inflow can be modelled based on, forexample, determined hydrocarbon production from natural fractures. Thosenatural fractures can be modelled within any simulation in order toallow for maximisation of production from those fractures.

In certain examples, the formation-modelling apparatus 1240 implementsthe method described above, e.g. in relation to FIG. 3, or implements atleast some of the features and/or steps described in relation thereto.However, it will be appreciated that this need not be the case and thatthe formation-modelling apparatus 1240 may instead implement otherprocesses or variations of the process of FIG. 3 that would be apparentfrom the present disclosure.

The formation-modelling apparatus 1240 is specifically configured toassume little or no damage to the formation during to drilling (e.g.based on the use of the drilling apparatus). As such, the modellingapparatus 1240 can use the determined formation parameters as accuratelyrepresenting the quality or properties of the formation at a particulardrilling location, and so can be used to control the drill bit 1212accordingly.

Here, the system 1200 is configured to use the determined formationparameters in order to verify/generate/revise a simulated model of theformation 100, which in turn can then be used to control the drillingapparatus based on the simulated model of the formation 100.

Control of the drilling apparatus 1210 may include adjustment toexpected trajectory of a drilled wellbore. Control may includeadjustment to the length of a wellbore. Control may include drilling ofside branches, or the like, from a wellbore. Control may includedeviation of the wellbore in order to increase natural fractureintersection, or area of exposure of natural fracture.

In other words, because of the use of the particular drilling apparatus1210 no, or at least very little, formulation damage has occurred. Assuch, a simulation model can be used to permit the accuraterepresentation of the formation in real or relevant time, based on dataacquisition (e.g. the identification of natural fractures), which inturn can be used so as to accurately control the drill bit 1212 and thusmaximise the potential production. In such cases, no hydraulic orchemical fracturing of the well bore is required, and any poor initialdata for low permeability reservoirs can be accommodated. In addition,collected data and simulation can be used to determine appropriatecompletion of a wellbore for optimum production.

Therefore, rather than the use of conventional data collection, drillingtechniques together with conventional hydraulic or chemical fracturingmethods, development and production from formations, and particularlylow permeability formations, can be improved using a combination ofreverse-circulation drilling apparatus, data acquisition apparatustogether with formation modelling apparatus. The use of drillingtechniques that do not unduly affect the formation 100 permit the use ofsimulated models together in a combined system 1200 that accuratelydepicts low permeability formations, and natural fractures, and thusallow for optimum drilling trajectories, without the need for hydraulicor chemical fracturing.

In addition, and as suggested, data collected (e.g. during drillingand/or post drilling) and models used by the above system 1200 may beemployed to determine appropriate casing points or completion intervals.In some examples, data acquired and corresponding modelling may be usedto determine a desire for hydraulic or chemical fracturing at aparticular location. The above described system 1200 may be additionallyused for such purposes (e.g. when identifying the absence of appropriatelevels of hydrocarbon production from a natural fracture).

In some examples, when drilling such wells, the use ofreverse-circulation drilling apparatus 1210 may allow for complex welltrajectories to be considered, which may be particularly useful whendeveloping and producing from shale formations, or the like, thatcomprise natural fractures 120.

For example, and with particular reference to FIG. 5, the drillingapparatus 1210 may permit drilling a primary wellbore 1300 using, asabove for example, the reverse-circulation drilling apparatus 1210.During such drilling, one or more secondary wellbores 1310 may bedrilled from the primary wellbore 1310. Each secondary wellbore 1310 maybe drilled in order to intersect one or more natural fractures 120 inthe formation 100. As with the primary wellbore 1300, the or eachsecondary wellbore 1310 can be drilled using reverse-circulationdrilling apparatus. This provision of secondary wellbores 1310 branchedfrom the primary wellbore 1300 may be particularly applicable, forexample, during development of an existing field or wellbore or after anexploration/appraisal of the formation. For example, the secondarywellbores 1310 may be arranged to maximise a number of natural fracturesintersected by the wellbores 1310, e.g. by optimizing orientation or thesecondary wellbores 1310 in terms of azimuth and/or deviation angle. Inthis way, the requirement for hydraulic fracturing may be minimisedand/or the number of surface locations to be developed may be minimised.

During such processes, the well may be permitted to flow during drillingof the primary wellbore 1300. In addition, the well may be permitted toflow during drilling of the or each secondary wellbore 1310. Duringdrilling of each secondary wellbore 1310, well and reservoir potentialmay be determined (e.g. determining hydrocarbon content and/orcomposition from wellbore inflow during drilling) in order to optimisewell design, and ultimately production.

In some examples, isolating one or more of the secondary wellbores 1310from the primary wellbore 1300 during drilling may be desired. In suchcases, isolation may be provided mechanically and/or chemically.

It will readily be appreciated that while the system of FIG. 4 may beused to provide primary and secondary wellbores, in the manner shown inFIG. 5, that nevertheless, in some examples, such wells may be drilledusing reverse circulation drilling without necessarily using thedata-acquisition apparatus 1230, or formation modelling apparatus 1240.In such examples, the use of reverse-circulation drilling, and thelittle or no impact on the formation, may permit suitable productionfrom such formations without the need for hydraulic or chemicalfracturing.

While in the above examples, shale formations (e.g. gas or oil typeshale reservoirs) have been described (e.g. accessible gas from lowpermeability sedimentary layers and natural fractures), the abovesystems, methods and apparatus may equally be used in coal bed methaneor coal seam gas type reservoirs where gas is accessed in coal depositsand the natural fractures and cleats in the coal.

The applicant discloses in isolation each individual feature describedherein and any combination of two or more such features, to the extentthat such features or combinations are capable of being carried outbased on the present specification as a whole in the light of the commongeneral knowledge of a person skilled in the art, irrespective ofwhether such features or combinations of features solve any problemsdisclosed herein, and without limitation to the scope of the claims. Theapplicant indicates that aspects of the present invention may consist ofany such individual feature or combination of features. In view of theforegoing description it will be evident to a person skilled in the artthat various modifications may be made within the scope of theinvention.

1. A method for computing expected production from a wellbore in a formation and/or hydrocarbon reserves associated with a formation, the formation having a plurality of naturally-occurring fractures, the method comprising: computationally modelling the formation; computing one or more wellbore positions intersecting some or all of the fractures; computing an expected production from the wellbore and/or reserves at least partially based on an expected wellbore damage associated with a particular type of drilling technique.
 2. The method of claim 1; wherein the one or more wellbore positions are computed using and/or based on the model of the formation; and/or the computed expected production of the wellbore is for the wellbore in the one or more wellbore positions.
 3. The method of claim 1 or claim 2, wherein: the expected production and/or reserves is/are at least partially based on the inflow from the naturally-occurring fractures; and/or the formation comprises a plurality of micro-fractures between the naturally-occurring fractures and the expected production and/or reserves is/are at least partially based on the inflow from naturally-occurring fractures together with inflow from micro-fractures.
 4. The method according to any preceding claim, wherein the method comprises subsequently deciding to drill and produce from a wellbore based on the expected production and/or reserves.
 5. The method according to any preceding claim, wherein the method comprises subsequently deciding to alter the initially-computed wellbore positions based on the expected production and/or reserves.
 6. The method according to any preceding claim, wherein the method comprises determining the need to fracture a near-wellbore formation surrounding the wellbore based on the expected production.
 7. The method according to any preceding claim, wherein the method comprises re-computing one or more of the wellbore positions, intersecting some or all of the fractures, in order to reduce, or eliminate, the need for hydraulic or chemical fracturing.
 8. The method according to claim 7, wherein the method comprises computing one or more of the wellbore positions in order to provide a particular or maximum recovery from the formation, without hydraulic or chemical fracturing.
 9. The method according to any preceding claim, wherein the particular technique is or comprises reverse-circulation drilling.
 10. The method according to any preceding claim, wherein the method comprises obtaining data, such as core data, from appraisal wells drilled specifically using the particular type of drilling technique for the purposes of modelling the formation.
 11. The method of claim 10, wherein the data is reviewed, and the formation potential re-appraised, by computationally modelling the formation using or based on at least some of the data.
 12. A method of forming a wellbore in a formation; the method comprising: using or determining parameters associated with a formation; computationally modelling the formation using the parameters; computing one or more wellbore positions, e.g. using the computed model, based on the type of drilling to be used for the formation; and drilling one or more of the wellbore positions.
 13. The method according to claim 12, the method comprising using data associated with the drilling operation to confirm at least one or each of the parameters associated with the formation and the computed model of the formation.
 14. The method of any of claim 12 or 13, comprising the method of any of claims 1 to 11, wherein the one or more wellbore positions are wellbore positions associated with a particular, optimum or maximum recovery from the formation.
 15. The method according to any of claims 12 to 14, wherein the method includes altering, or modifying, one or more of: (i) the determined parameters (ii) the computed model; and (iii) the wellbore positions, based on an identified difference between data associated with drilling, and expected data associated with the parameters or model.
 16. The method according to any of claims 12 to 15, the method comprising real-time monitoring of data while drilling.
 17. A drilling system comprising: reverse-circulation drilling apparatus; data-acquisition apparatus in communication with the drilling apparatus, the data acquisition apparatus being configured to determine formation parameters when drilling using the drilling apparatus; and formation-modelling apparatus, in communication with the data acquisition apparatus, and configured to use the determined formation parameters with a simulated model of the formation so as to allow for control of the drilling apparatus based on the simulated model of the formation.
 18. The system according to claim 17, wherein the formation modelling apparatus is configured to implement the method of any of claims 1 to 11 and/or the system is configured to implement the method of any of claims 12 to
 16. 19. The system according to claim 18, wherein the system is configured for use with low permeability formations, such as shale-rock formations.
 20. The system according to any of claims 17 to 19, wherein the drilling apparatus comprises at least one flow control device, the flow control device configured to prevent or inhibit undesired flow of fluids from uncontrollably reaching a surface.
 21. The system according to claim 20, wherein the flow control device is configured to regulate the flow of fluids from a formation to the data acquisition apparatus.
 22. The system according to any of the claim 20 or 21, wherein the flow control device permits isolation and testing of selected zones in the formation.
 23. The system according to any of the claims 17 to 22, wherein the data-acquisition apparatus is configured to sample materials, including liquids, gases and/or cuttings provided during drilling, in order to determine formation parameters.
 24. The system according to claim 23, wherein the data-acquisition apparatus is configured to compute or determine the location of natural fractures in the rock formation, based on sampled materials from a well.
 25. A system according to claim 24, wherein the data-acquisition apparatus is configured to determine hydrocarbon production, or liberation, at a particular drilling region or location, and wherein a determined relative increase in hydrocarbon production indicates the presence of a natural fracture at that drilling region or location.
 26. A system according to any of claims 17 to 25, wherein the data-acquisition apparatus is configured to determine formation parameters in real time and is configured to communicate determined parameters to the formation-modelling apparatus in real time.
 27. A system according to any of claims 17 to 26, wherein the formation-modelling apparatus is configured to use computational fluid dynamics using finite volumes to model a formation being drilled.
 28. A system according to any of claims 17 to 27, wherein the formation-modelling apparatus is configured to verify, generate and/or revise a simulated model of the formation based on determined formation parameters.
 29. A system according to any of claims 17 to 28, wherein the formation modelling apparatus is configured to model wellbore inflow, assuming little or no damage to the formation during to drilling.
 30. A system according to any of claims 17 to 29, wherein the system is additionally configured to control the drilling apparatus based on the simulated model of the formation.
 31. A system according to claim 30, wherein control comprises one or more of: adjustment to expected trajectory of a drilled wellbore; adjustment to the length of a wellbore; drilling of side branches; deviation of the wellbore, in order to increase natural fracture intersection.
 32. A system according to claim 30 or 31, wherein control includes drilling a primary wellbore and drilling one or more secondary wellbores from the primary wellbore, each secondary wellbore being drilled in order to intersect one or more natural fractures in the formation.
 33. A system according to claim 32, wherein the one or more secondary wellbores are arranged to maximise a number of natural fractures intersected by the wellbores by optimizing orientation or the secondary wellbore(s) in terms of azimuth and/or deviation angle.
 34. A system according to claim 32 or claim 33, wherein the formation-modelling apparatus is configured to update and/or optimise the model based on core data acquired for the primary and/or secondary well bore(s).
 35. A method of drilling a formation comprising: drilling a primary wellbore using reverse-circulation drilling apparatus, and drilling one or more secondary wellbores from the primary wellbore, each secondary wellbore being drilled in order to intersect one or more natural fractures in the formation.
 36. The method according to claim 35, wherein the or each secondary wellbore is drilled using reverse-circulation drilling apparatus.
 37. The method according to claim 35 or claim 36, wherein at least the one or more secondary wellbores are drilled during development of an existing field or wellbore or after an exploration/appraisal of the formation.
 38. The method according to any of claims 35 to 37, wherein the one or more secondary wellbores are arranged to maximise a number of natural fractures intersected by the wellbores by optimizing orientation or the secondary wellbore in terms of azimuth and/or deviation angle.
 39. The method according to any of claims 35 to 38, comprising permitting the well to flow during drilling of the primary wellbore.
 40. The method according to any of claims 35 to 39, comprising permitting the well to flow during drilling of the or each secondary wellbore.
 41. The method according to any of the claims 35 to 40, comprising determining well and reservoir potential during drilling by determining hydrocarbon content and/or composition from wellbore inflow during drilling.
 42. The method according to any of the claims 35 to 41, comprising isolating one or more of the secondary wellbores from the primary wellbore during drilling, wherein such isolation is provided mechanically and/or chemically.
 43. The method according to any of the claims 35 to 42 comprising determining the location of natural fractures in rock formation, based on sampled materials from a well, in order to determine desired location(s) for secondary wellbores.
 44. The method according to claim 43, comprising determining hydrocarbon production, or liberation, at a particular drilling region or location in order to determine the location of natural fractures in order to determine desired location for secondary wellbores.
 45. The method according to claim 44, wherein a determined relative increase in hydrocarbon production during drilling indicates the presence of a natural fracture at that drilling region or location.
 46. The method according to any of the claims 35 to 45, comprising acquiring data from drilling in order to determine formation parameters, and using the formation parameters with a simulated model of the formation so as to allow for control of the drilling apparatus based on the simulated model of the formation.
 47. The method according to claim 46, wherein the formation parameters are used to verify, generate and/or revise the simulated model of the formation.
 48. The method according to any of the claims 35 to 47, wherein the method is used in shale-rock formation.
 49. The method according to any of claims 35 to 48, comprising acquiring core data for the primary and/or secondary well bore(s) to collect data for the formation in which the natural fractures and hydrocarbons are present and optionally updating the simulated model based on the data and/or core data.
 50. An unconventional hydrocarbon reservoir comprising: a primary wellbore having been drilled using reverse-circulation drilling apparatus, and one or more secondary wellbores having been drilled from the primary wellbore, the or each secondary wellbore intersecting one or more natural fractures in the formation.
 51. The unconventional hydrocarbon reservoir according to claim 50, wherein the unconventional hydrocarbon reservoir is or comprises or is comprised in a shale rock formation. 